California, Oregon, Utah, and Washington have already developed most (if not all) of their prime-quality in-state resources.

You would think that the more wind and solar power is added over a wide area, the more fossil fuel power plants you could finally get rid of. But the more you depend on wind or solar power, the less certain it can be counted on at peak demand times, even over large areas, due to seasonal patterns, large storms, and vast low or high pressure systems (wind more so than solar).

California studied in-state renewables versus importing Wyoming wind power, because California has developed all of its best wind, solar, and geothermal resources, and found it would require adding 957 MW of dispatchable natural gas plants because Wyoming wind doesn’t blow when California demand is highest (NREL 2014).

Furthermore, even if California and the 10 other states in the western region (WECC) completely develop and share their best wind, solar, and geothermal resources (highly unlikely, states prefer to keep their best resources in-state and not pay billions for expensive transmission lines that benefit other states), reserving less productive, more expensive, widely dispersed locations for in-state generation, the potential 148 TWh of prime (*) and 230 TWh of non-prime wind, solar, and geothermal generation don’t add up to the current 481 TWh of fossil and nuclear power production. States prefer to use their in-state prime resources for many reasons and are not likely to build expensive transmission lines to export power (EIA 2012, NREL 2013 below).

The West’s largest surpluses of prime-quality utility-scale renewable resource potential will be in Colorado, Montana, New Mexico, and Wyoming (wind power); Idaho (geothermal power); and Nevada (geothermal and solar power). To the extent that future scarcity of untapped prime-quality resources could signal potential demand, the most likely importing states are California, Oregon , Utah, and Washington. We categorize Arizona as a potential exporter of solar power (which the state will most likely have in surplus in 2025) and a potential importer of prime wind and geothermal power.

By the time states meet their Renewable Portfolio Standards (RPS) new prime-quality renewable resources available for additional development may be scarce. This will require developing resources of lower quality that will tend to cost more.

Whether the timeline for securing PPAs for new renewable projects can provide competitive developers with investment signals that are comparable to what rate base mechanisms provided to regulated utilities when they expanded their baseload capacity [will private companies earn enough money to build renewables & will the transmission lines be there to induce them to do so]

How states balance post-2025 regional renewable energy expansion in the context of other policy objectives such as DG, in-state economic development, and protecting habitat.

The chart below shows the amount of electricity moving across state borders. California’s in-state net generation is less than its in-state retail sales by about one-quarter, making it a net importer. In contrast, about 43 TWh of all the electricity generated in the So uthwest each year is used somewhere other than the state where it was generated.

California, Oregon, Utah, and Washington have already developed most (if not all) of their prime-quality in-state resources.

Their non-prime resources could be of sufficient quantity to meet the balance of their forecasted 2025 requirements, but the cost is likely to be higher than the cost of resources developed prior to 2012.

The western states all together will need between 127 TWh and 149 TWh of renewable energy in 2025 to meet targets stipulated by current state laws. California accounts for about 60% of this demand. Renewable energy projects either existing or under construction in the western United States as of 2012 can supply an estimated 86 TWh.

Colorado, Montana, Nevada, and New Mexico each has within its borders more untapped prime-quality renewable resources than it needs to meet the balance of its forecasted requirement for 2025. Wyoming and Idaho have no requirement, but they have large supplies of prime-quality renewable resources. Arizona has sufficient prime and near-prime solar resources to meet the balance of its forecasted requirement for 2025. It has a limited amount of non-solar resources, none of which is prime quality.

All western states with renewable energy targets are making progress toward their goals. Some, however, show signs of reaching the end of their stocks of prime-quality developable resource areas.

Potential technological breakthroughs, such as enhanced geothermal systems or low-speed wind turbines, could improve the viability of resource areas that with current technologies are marginally productive. By 2025, when all current RPS requirements will have matured to their ultimate target levels, the largest untapped surpluses of prime-quality renewables will be in Wyoming, Montana, Colorado, New Mexico, Idaho, and Nevada.

If RPS compliance using in-state resources is a strong preference for renewable resource planning, then utilities and regulators in California, Oregon, and Washington (and possibly Arizona and Utah) may need to weigh the acceptability of meeting the last increments of their targets with a small amount of high-cost renewables that require no major investment in new transmission . By then, most of their low-cost local resources will likely be in use already.

Table ES -1 ranks the 15 resource- to-market combinations that scored highest in the evaluation methodology used in this study

Geothermal power from Idaho to California. These resource paths have the highest likelihood of being reasonably competitive with natural gas generation in 2025 even if current transmission costs were to double.

An index score less than 1.0 indicates a resource with a delivered cost that is still below the relevant state benchmark even if current transmission costs are double. pages 145-150 have costs if prices go up10% or down 10%

Long- term trends in capital costs are difficult to predict, so this study included a sensitivity analysis to test how a 10% change in a technology’s assumed 2025 cost would affect its relative competitiveness as estimated in this study.

The most pronounced cost sensitivity was for utility- scale solar power from Nevada and Arizona delivered to California. If costs were to fall 10% below the base-case assumptions used in this analysis, solar power from Nevada and Arizona would be close to parity with CCGT in California . The two resource paths would rank third and fourth among the potential paths with the greatest likelihood for value in a post-2025 West. A cost decrease would also favor California’s own solar resources, however, so the net impact on imports would probably be related to siting constraints. Results for wind power did not change significantly under different cost assumptions. Wyoming wind delivered to Utah and California remained below or close to parity with natural gas. Other wind resource paths were slightly less competitive. Paths for geothermal power were sensitive to cost changes. The reduced-cost scenario brought Idaho geothermal to within 10% of competitiveness with natural gas in California. Higher costs, on the other hand, could put geothermal power 30% to 85% above the forecasted cost of a new CCGT in 2025.

Results from this study suggest that geothermal power will likely remain more costly on an all-in, per- MWh basis than equivalent CCGT or other renewable power options in the West out to 2025, barring a significant breakthrough in current technology cost or performance. For wind and solar built in ideal locations, the gap could become small.

1.2 WREZ Phase 1 and Phase 2 : Locating the Best Resources

This study builds on a number of preceding related efforts. In 2007, WGA asked DOE for federal support to identify renewable energy zones in the Western Interconnection. The Western Renewable Energy Zone (WREZ) initiative contemplated several phases, the first of which was a cross-sectional assessment of renewable resources throughout the West. Phase 1 was conducted for WGA by the National Renewable Energy Laboratory (NREL), under the guidance of a steering committee comprising state and provincial energy officials and with input from a diverse group of stakeholders.

Lawrence Berkeley National Laboratory (LBNL) did a transmission analysis linking the Phase 1 resource hubs with the interconnection’s largest demand centers. The centerpiece of that work was a tool that stakeholders can use to compare scenarios for delivering renewable resources from selected zones to selected load centers

Utilities are focused on developing renewable resources in or close to their service areas. Among the reasons is that resources close to load may not require new high-voltage transmission and, therefore, are easier to develop in a more incremental manner. Even where transmission capacity is available, the economics of distant, higher-quality resources may be diminished by pancaking of charges— purchasing transmission service separately from each provider whose lines the power crosses to reach loads. In-state resources also are a more obvious nexus with state public interest standards for siting and cost recovery, reducing development timelines, and risk for utilities. “Rate pancaking” is a common term in electricity regulation. The term is used throughout this report to refer to the accumulation of transmission charges between the point of generation and the point of delivery to end-use customers.

Utilities are less interested in resources from [other states] unless transmission already exists or there is a high degree of certainty for the timely completion of transmission. Two-thirds of the utilities interviewed say state policies or regulations impede development of interstate transmission. Key areas of concern are local siting processes, inconsistent siting standards across borders, and cost recovery risk. Public utilities commissions (PUCs) and provincial energy ministries cited the following hurdles: demonstration for a given state that a line is needed and will serve the public interest, lack of eminent domain authority, multiple uncoordinated approvals required by various levels of government, and cost recovery processes.

Therefore Utilities in a state will prefer using in-state prime resources whenever possible to meet their RPS requirements and Prime out-of- state resources will not be preferred unless there are no more prime in-state resources.

2.2.3.3 Planned Renewable Energy Supply

California’s IOUs plan for future renewable energy needs through their long- term procurement plans. Public utilities and independent power producers plan other facilities. California Energy Commission data indicate that 19 TWh/year of new renewable energy generation is in some stage of planning. While some of these projects might not happen, historical data indicates that 79% of all generation from planned projects seeking contracts has been successfully delivered. The majority (53%) of failed generation has been solar thermal technology; however, solar thermal projects are large, and these contracts were no more likely to fail than other technologies in terms of number of contracts.

California currently has over 3.2 GW of solar capacity under construction (both CSP and utility-scale PV. 63 More than 1 GW of wind and 53 MW of biomass projects are under construction as well.

2.2.3.4 Undeveloped Renewable Energy Supply

The state’s renewable energy zones have an estimated 10 TWh of developable solar resources that have not yet been tapped. Solar projects to date, however, exceed the amount of developable prime and borderline prime resources estimated to exist within California’s zones. 64 This suggests that California’s remaining solar resource areas tend have less solar exposure than what has already been developed and might be less productive. Future opportunities for renewables other than solar appear to be getting tighter. About half of the geothermal potential identified in southern California was developed as of 2012, and what was planned as of early 2013 amounted to an additional 17%. Existing wind development exceeds what was estimated to be in a renewable energy zone, indicating that developers are already looking at areas where the potential is less concentrated and possibly lower in productivity. Data for biomass also suggest future development will be outside a renewable energy zone. Most of the identified potential for small hydro was outside a zone, and as of 2012 about 10% of it had been developed.

In short, while individual project opportunities might exist based on the conditions afecting particular sites, systematic indicators suggest that California overall could be approaching supply constraints if restricted to in-state resources. At some point, options for new in-state renewable energy development might be dominated by areas that are less productive or more environmentally sensitive.

Figure 2-11 Renewable resource potential in California shows the supply curves for the screened solar and non- solar resources identified within California’s renewable energy zones. They indicate the total estimated generating potential, ordered by the estimated cost of delivered power from these resources. The supply curves identify more than 21 TWh per year of generating potential from non- solar renewables. Total developable solar areas have the potential to provide between 41 TWh and 55 TWh, depending on the technology employed. Screened resource areas estimated to exist in renewable energy zones. Costs are based on technical estimates. Curves are for all resource potential regardless of whether developed or undeveloped. Chart for solar potential indicates cost curves for different solar technologies as they apply to the same screened resource areas. Solar development to date amounts to about 20,000 GWh per year for solar and thermal technologies combined

Figure 2-12 Developed resources in California (existing, under construction) shows the resources that have already been developed, also ordered by the estimated cost of their development. 65 Nearly 59 TWh of solar and non- solar renewable energy generation has been developed in California, at costs that have typically ranged from $54/MWh to $133/MWh. 66 Costs for wind, geothermal, and biomass generation are generally lower, with generation from solar technologies generally higher.

Table 2-2. California Resources Estimated to be Available for Future Development. The first two data columns show the identified resource potential after screening out areas that are off-limits to development or are difficult to develop economically due to physical characteristics of the terrain. Screened resources that are part of a geographic concentration are assigned to a zone; the second column shows isolated resources that may be developable but are not part of a renewable energy zone. The last two columns show what has already been developed (or is currently under development) within the state borders up to the end of 2012 and its estimated cost. 68 Most of the biomass and small hydro developed to date— typically small installations that are scattered widely across the state — are outside a renewable energy zone. Most of the geothermal power that has already been developed is at two older projects located in the northern part of the state and outside of a renewable energy zone. The geothermal resources quantified in the WREZ analysis are located in the Imperial Valley of southern California.

The state’s most abundant renewable resource is solar, with more than 37 TWh of potential within the renewable energy zones. More than 16 TWh of solar PV and nearly 11 TWh of solar thermal have been developed within the state. This leaves between 17 TWh and 19 TWh of developable potential, depending on which solar technology is chosen.

Conclusion

Resources within California’s renewable energy zones, combined with what it is already importing from other states, could provide enough generation to meet low demand scenarios to 2025. It might not be enough if demand turns out to be higher, however. In this case, California would need to draw more heavily from in-state renewable resources not located in a concentrated zone or it might need to draw on out-of- state resources. Moving toward a post-2025 environment, California’s undeveloped in-state renewable resources will become scarce, more costly, and more widely dispersed...most of the high-quality renewable resources areas within the state will already have been developed.

Wyoming:Prime, export-quality wind resources that have not yet been developed could provide at least 42.7 TWh annually, almost twice Wyoming’s projected total retail sales in 2025. The state has an additional 1.7 TWh of non-prime wind and biomass resources.

The overwhelming majority (87%) of Wyoming’s electricity is currently produced from coal-fired generating facilities. Conventional hydropower (constructed prior to 2000) supplies approximately 2% of the electricity. The remaining 10% of the electricity produced in Wyoming is generated from wind power. EIA data show no utility-scale solar or biomass facilities currently exist in Wyoming, so almost the entirety of Wyoming’s renewable electricity is generated from wind. One very large baseload plant located in Wyoming is of note: the 2,117- MW coal-and oil-fired Jim Bridger power plant exports more than 11 TWh of power annually out of Wyoming, amounting to over 23% of the total electricity generated in Wyoming.

The best Wyoming wind areas that are likely to remain undeveloped in 2025 have a total energy potential that is more than 2.5 times the amount of electricity produced annually at the Jim Bridger Generating Station, the West’s second-largest coal plant located in the southern part of the state. This includes only those wind resources with an annual capacity factor estimated at 40% or better. About 37.3 TWh could be developed at a busbar cost of $69–$81 /MWh , assuming no financial incentives.

Colorado: Colorado has about 53.5 TWh of unused prime wind energy resources. This is twice what is needed to meet the expected demand for renewable energy in 2025 and is about equal to Colorado’s total retail electricity sales in 2012. This leaves a significant amount of prime-quality wind for potential export to other states. It already exports some wind power besides importing a small amount of wind power from Wyoming. Colorado also has significant quantities of non-prime solar, biomass, and wind resources suitable to meet in-state demand.

Idaho: An analysis of the unused prime resources reveals that 2.1 TWh of prime resources (from geothermal) could be developed for exports to other states. In addition, another 2.8 TWh of non-prime wind and biomass resources could potentially be developed as well.

Montana:Prime, export-quality wind resources that have not yet been developed could provide at least 30.5 TWh annually. The state has an additional 3.3 TWh of non-prime wind and biomass resources that could meet in-state demand.

Nevada: Nevada’s projected 2025 surplus of prime-quality solar potential is between 3 TWh and 6 TWh annually. The amount available for post-2025 development will depend on how much Nevada uses for its own renewable energy goal. Prime, export-quality geothermal and solar resources that have not yet been developed could provide at least 12.7 TWh annually (6.1 TWh prime solar in the south and 6.6 TWh of geothermal further north). The state has an additional 36.8 TWh of non-prime solar, biomass, and wind resources that could meet in-state demand

New Mexico: Prime, export-quality wind resources that have not yet been developed could provide at least at least 3.8 TWh annually. The state has an additional 75 TWh of non-prime wind, solar, and biomass resources that could meet in- state demand.

Arizona:Prime, export-quality solar resources that have not yet been developed could provide at least 2.7 TWh annually. The state has an additional 44 TWh of non-prime solar, biomass, and wind resources that could meet in-state demand

Oregon: Most of Oregon’s renewable energy development to date has been wind power, but much of that is exported to other statesand there is limited potential for further expansion. More than half of Oregon’s electricity is produced from conventional hydropower plants constructed prior to 2000 are categorized as conventional generation), with gas and coal plants providing over 32% of the electricity produced. Explored geothermal resources could provide up to 5.7 TWh annually, but little has been developed to date. The state has an estimated 5.3 TWh of biomass and solar potential, also largely undeveloped.

Utah: Utah has already tapped most of its best renewable resources. Existing development exceeds the amount of prime wind resources estimated to be in the state’s renewable energy zones, although some 700 GWh worth of geothermal baseload potential remains untapped. The state already imports a large amount of low-cost wind power from Wyoming. Utah has an estimated 0.7 TWh of undeveloped geothermal resources. Its renewable energy zones also contain about 4.2 TWh of non-prime wind and biomass resources.

Washington: Washington can meet the balance of its current renewable energy targets with in-state resources, but there is likely to be little left for subsequent demand beyond 2025, there is little left in the way of undeveloped prime-quality resources. Power from wind and biomass already flows across the state’s border in both directions, with some exports and some imports. Washington has additional undeveloped wind, biomass, and hydro resources, but little of it is prime quality. Most of these untapped resources are likely to be relatively expensive to develop and are not likely to be competitive in a post 2025 market. Washington will need between 8.4 TWh and 12.2 TWh of renewable energy in 2025 to meet targets stipulated by current state law. • Renewable electricity projects either existing or under development as of 2012 can supply 8.8 TWh annually. About one-third of the state’s current renewable energy generation—primarily wind power—is exported. • Washington has 4.0 TWh of non-prime wind, biomass, and small hydro resources that could meet in-state demand.Wind resources already developed in Washington’s renewable energy zones are more than the amount of prime-quality wind estimated to be in the zones. As with Oregon, this suggests possible supply constraints affecting future wind development in the state. Another 4 TWh of lower-quality wind, biomass, and hydro resources are yet undeveloped and would be competitive to meet in-state demand. Most of these additional resources—2.5 TWh—are hydropower.

This shows the Western Interconnection’s coal and nuclear plants with generating units 500 MW or larger and how power from these stations flows commercially across the region. Most serve demand in more than one state, and most send a share of their output to California.

In the West, proximity to fuel and cooling water had a greater bearing on siting than did proximity to load. The coal gigaplants took advantage of location, maximizing their economic and operational efficiency by siting close to their fuel supplies and to sources of cooling water. For example, th e Navajo Generating Station, the West’s largest coal plant, is located on the Navajo Reservation in northern Arizona just 3 miles from Glen Canyon Reservoir and is only 50 miles from the coal mine on the Navajo and Hopi reservations that provides its fuel. Similarly, the nuclear reactors built to generate electricity had to be located near abundant sources of cooling water. The San Onofre and Diablo Canyon nuclear stations were built near the ocean so they could use seawater for once -through cooling. 197 The Palo Verde plant was designed to use reclaimed wastewater for cooling and was built near Phoenix where wastewater was sufficient and easily accessible.

Renewables: As with baseload gigaplants, renewable energy depends on location for operational efficiency and economies of scale. There are differences, however. An individual unit at a gigaplant was a supersized supercritical steam unit linked to load along a supersized transmission corridor. For renewables, economy of scale means efficiently aggregating many small units of production—for example, hundreds of 2- to 3- MW wind turbines with a common point of interconnection, rather than the same amount of capacity embodied in a single supercritical thermal unit.

The locational factors affecting renewables pertain to the consistency of the energy inputs: wind, sunshine, and underground heat. The quality of the natural resources affects the productivity of the technology used to create electricity, which in turn affects the technology’s economic viability. The WREZ Phase 1 analysis identified a select few areas in the West where wind was consistent enough to yield capacity factors of 40% or better, across contiguous areas capable of accommodating several gigawatts of capacity. High capacity factors mean the same amount of capital investment produces more electricity, with potential economies that can favorably affect customer rates. Economy of scale with respect to transmission is a key point for reducing the cost of future renewable energy development. One 500-kV line is about half the cost of four 230­ kV lines capable of moving the same quantity of power. The large line loses less electricity between the point of generation and the point of delivery to load, and it requires right-of-way along only one corridor rather than four.

Table x. Can we build enough renewables by 2050 or ever? All figures are in TWh/year. 744.6 total generation – 190.8 hydropower – 9.6 other renewables is another 544 of renewable generation needed. If all prime (148) is built then the shortage is around 400. It isn’t likely the 230 on non-prime locations will be built without expensive transmission as well as major technical improvements that reduce costs substantially